Methods and compositions for improving hydrocarbon recovery by water flood intervention

ABSTRACT

Methods useful in improving hydrocarbon recovery from subterranean formations using relative permeability modifier (RPM) macromolecules are described. The RPMs are typically crosslinked RPMs having K-values from 250-300 which, when injected into an injector well associated with a producer well, redirect the production water so as to improve the injection profile of the well and simultaneously improve hydrocarbon recovery from the producer well.

FIELD OF THE INVENTION

The present invention provides methods of enhanced recovery of hydrocarbons from subterranean formations. In particular, the present invention provides methods for improving the recovery of hydrocarbons from subterranean formations using relative permeability modifier macromolecules.

DESCRIPTION OF RELATED ART

Water production is always a harbinger of problems in a subterranean well, with water cuts in oil producing wells increasing as time passes and oil fields become more mature. The source of the water is often either formation water or injected water used for the purpose of reservoir maintenance. In other instances, heterogeneities encountered in reservoir rocks can cause water channeling through higher permeability streaks/hairline fractures, or near wellbore water coning at early periods in the well's productivity life span, often due to limited reservoir thickness or excessive pressure drawdowns.

Such water production can cause a variety of problems. It can cause scaling problems in susceptible wells, induce fines migration or sandface failure, increase corrosion of tubulars, and sometimes even kill wells by hydrostatic loading, among other things. Clearly, while water production is an inevitable consequence of oil production, it is often desirable to defer its onset, or at least its rise, for as long as possible during hydrocarbon production.

Numerous strategies, both mechanical and chemical, have been employed over the years in attempts to achieve these goals, or at the least use the water flow to aid in hydrocarbon production. These approaches have ranged from simple shut-off techniques, such as cements, mechanical plugs, and inorganic gel squeezes to isolate watered out zones, to more advanced concepts, such as the use of several types of gel systems with varying degrees of success in the control of water and water production. Among these, three main chemical gel types have emerged as showing promise in subterranean water treatments: permeability blockers or gellants, which plug pore spaces and prevent fluid movement, often by means of a controlled, delayed chemical reaction, such as precipitation or swelling to form a three-dimensional “gel”; Disproportionate Permeability Reducers (DPR) and/or Selective Permeability Blockers (SPB), which also plug the pore spaces, restricting fluid movement, but do not precipitate, swell, or viscosify significantly in the presence of hydrocarbons, thereby reducing water relative permeability; and Relative Permeability Modifiers (RPMs), which, generally speaking, are water-soluble, hydrophilic polymer systems that, when hydrated, produce long polymer chains that loosely occupy pore spaces in the rock. Being strongly hydrophilic, RPMs attract water and repel oil and, as a net result, exert a “drag force” on water flow in the pores with a minimal effect on oil flow.

Various methods have been proposed for increasing hydrocarbon production from subterranean formations with water problems. For example, U.S. Pat. No. 4,485,871 suggests a method for recovering hydrocarbons in which an alcohol is injected into the formation, followed by an aqueous alkaline solution. However, this type of methodology is particular to diatomaceous formations. In particular, hydrocarbon recovery using this method is reportedly not optimum in formations that are deeply buried and/or have not been extensively exposed to the atmosphere or oxygen bearing formation water, resulting in an interfacial tension and oil/rock wettability issues in these formations.

Davis, in U.S. Pat. No. 4,828,031, offers a method for recovering oil from subterranean formations, in which a solvent is injected into the formation, followed by an aqueous surface-active solution. The aqueous surface-active solution is described to contain a diatomite/oil water wettability improving agent and an oil/water surface tension lowering agent. It is also suggested that the method can be supplemented by the injection of water and/or steam into the formation, at a pressure just below that where a long fracture may be induced.

The use of numerous relative permeability modifiers for the control of production water have been described in the art. For example, U.S. Pat. No. 6,228,812 describes a chemical composition treatment that selectively reduces water production by the employment of relative permeability modifiers (RPMs). According to the specification, the use of RPMs entails low risk to oil production, as the polymers reportedly reduce the water permeability downhole without adversely affecting oil permeability. The use of RPMs for water control is also reported to be low in cost and low in application cost as the use of such compositions does not require expensive equipment for their application.

In U.S. Pat. No. 6,228,812, compositions and methods for modifying the permeability of subterranean formations is described, for the purpose of selectively reducing the production of aqueous fluids. The compositions are described to include relative permeability modifiers which include copolymers with hydrophilic and anchoring monomeric copolymer units that can be added to well treatment fluids to form water control treatment fluids.

However, while the use of polymeric compositions are exhibiting increased utility and promise for downhole applications, many water control compositions, and even some relative permeability modifiers, do not always impart extended effectiveness, or exhibit utility in formations having permeability's greater than 1 Darcy. Thus, there exists a need for methods to increase hydrocarbon production from hydrocarbon-bearing formations using compositions and methods that do not adversely affect oil production or permeability through the formation.

SUMMARY OF THE INVENTION

The present invention is directed generally to methods for increasing hydrocarbon production from a hydrocarbon-bearing formation, using relative permeability modifier macromolecules or microgels. In a first aspect, the present invention provides a method for increasing hydrocarbon production from a production well in a hydrocarbon-bearing formation wherein there is at least one injector well associated with the production well, the method comprising the step of introducing an aqueous composition comprising a relative permeability modifier macromolecule into the at least one injector well. In accordance with this aspect, the relative permeability macromolecule can be a microgel, be deformable, have a K-value from about 200 to about 1,000, and/or be present in the aqueous composition in a concentration from about 15,000 ppm to about 50,000 ppm.

In a further aspect of the present invention, a method for increasing hydrocarbon production from a production well in a hydrocarbon-bearing formation having at least one injector well associated with the production well is provided, wherein the method comprises the steps of introducing an aqueous composition comprising a relative permeability modifier (RPM) macromolecule into an injector well in a permeable formation in an amount effective to enhance oil production from the production well, and continuing the injection of the RPM macromolecule into the at least one injector well for a time sufficient to increase oil flow from the formation to the production well where it is subsequently produced to the surface. In accordance with this aspect of the invention, the RPM macromolecule is capable of redirecting water flow through the hydrocarbon-bearing formation to provide an improved injection profile, and/or the method can further comprise the step of forming a treating solution comprising at least one RPM macromolecule prior to the introducing step.

In yet another aspect of the present invention, a method for increasing hydrocarbon formation from a production well in a hydrocarbon-bearing formation having at least one injector well associated with the production well is provided, the method comprising the steps of introducing an aqueous composition of a water-soluble, crosslinked, RPM macromolecule comprised of a terpolymer, copolymer, or homopolymer of a vinyl acetamide and a sulfonated vinyl monomer into an injector well, and continuing the injection for a period of time sufficient to increase oil flow from the formation to the production well, where the oil can be subsequently produced. In accordance with this aspect of the invention, the RPM macromolecule can further be classified as a microgel, have a weight average molecular weight from about 10,000 to about 50,000,000 g/mol, and/or a K-value from about 200 to about 1,000.

In a further aspect of the present invention, a method for increasing hydrocarbon production from a production well in a subterranean formation is provided, the method comprising introducing an aqueous treating solution comprising a crosslinked relative permeability modifier (RPM) macromolecule into the subterranean formation through an injector well that is associated with the production well. In accordance with this aspect of the invention, the crosslinked RPM macromolecule comprises a terpolymer, copolymer, or homopolymer comprising an anchoring monomer and a hydrophilic monomer, and is capable of redirecting water flow through the hydrocarbon-bearing formation to provide an improved injection profile.

In another aspect of the present invention, a method for increasing hydrocarbon production from a production well in a hydrocarbon-bearing formation, wherein there is at least one injector well associated with the production well, the method comprising introducing an aqueous water-control fluid composition comprising a crosslinked relative permeability modifier (RPM) macromolecule and an aqueous base fluid into an injector well in a permeable formation, and continuing the injection of the crosslinked RPM macromolecule into the injector well for a time sufficient to increase oil flow from the formation to the production well where it is subsequently produced to the surface via the producer well. In accordance with this aspect of the present invention, the crosslinked RPM macromolecule is a terpolymer, copolymer or homopolymer comprising a hydrophilic monomeric unit and a vinyl amide unit, is capable of redirecting water flow through the hydrocarbon-bearing formation to provide an improved injection profile, and is introduced into the hydrocarbon-bearing formation prior to, in conjunction with, or after a stimulation operation.

In yet another aspect of the present invention, a method for enhancing hydrocarbon recovery from a reservoir or formation containing substantially immobile hydrocarbons is provided, wherein the method comprises drilling and completing at least one injector well in a subterranean formation in proximity to a producer well, or converting a producer well into an injector well in proximity to other producer wells; directing an aqueous mixture comprising a crosslinked relative permeability modifier (RPM) macromolecule into the injector well, wherein the RPM macromolecule is present in an amount effective to redirect water flow in the subterranean formation and thereby increase hydrocarbon flow therefrom; and continuing the injection of the aqueous treating composition into the injector well for a time sufficient to increase flow of hydrocarbons from the formation towards the producer well, where it is subsequently produced to the surface via the producer well.

DESCRIPTION OF THE FIGURES

The following figures form part of the present specification and are included to further demonstrate certain aspects of the present invention. The invention may be better understood by reference to one or more of these figures in combination with the detailed description of specific embodiments presented herein.

FIG. 1 is a schematic representation of one aspect of the present invention, illustrating RPM microgel flow from injector wells towards producer wells.

FIG. 2 is a graphic representation of the parallel core flood test of compositions in accordance with the present invention.

DETAILED DESCRIPTION OF THE INVENTION

The present invention is directed to well treatment methods useful in redirecting water in a subterranean formation so as to improve the injection profile of the well and increase hydrocarbon production from the well. Illustrative embodiments of the invention, as well as illustrative methods of operation of the unit, are described below in detail.

Composition

The compositions of the present invention are aqueous treatment compositions containing one or more relative permeability modifier (RPM) macromolecules. As used herein an RPM macromolecule refers to a deformable, polymeric composition that comprises at least one hydrophilic monomer which aids in the RPM adhering to the formation and adds to the water/brine solubility; and at least one anchoring monomeric unit to cause the RPM to adhere to the formation. Further general characteristics of the relative permeability modifier macromolecules as used herein include those RPM macromolecules having K-values from about 200 to about 1,000 (which can be controlled by the concentration of the starting monomers and/or the amount of crosslinking), and those RPM macromolecules that are crosslinked, or both. Such RPM macromolecules also include soft “microgels”, which as used herein refers to those RPM macromolecules which are crosslinked during their manufacture and have a weight average molecular weight of from about 10⁴ to 10⁸ g/mol. These RPM microgels typically have a diameter from about 0.001 micron to about 500 micron, and more typically from about 0.001 micron to about 100 micron.

The relative permeability modifiers suitable for use in the methods of the present invention are any polymers which can either impede the production of water and/or redirect water through permeable formation materials. Suitable RPMs include copolymers, homopolymers, or terpolymers comprised of hydrophilic monomers, at least one anchoring monomeric unit, an optional secondary anchoring unit, and one or more filler/spacer monomer units. Optionally, the RPMs can provide grafting sites for the inclusion of organosilicon compounds. Suitable relative permeability modifiers include those described in U.S. Pat. Nos. 5,735,349; 6,169,058; 6,465,397; and 6,228,812, herein incorporated by reference. Optionally, and in accordance with the present invention, the RPM can include one or more organosilicon compounds. Preferred RPM macromolecules suitable for use within the present invention are AquaCon™, AQUATROL™ I , and Aquatrol V (available from BJ Services Company, Houston, Tex.).

The RPM macromolecules suitable for use in the present invention have weight average molecular weights ranging from about 10,000 g/mol to about 50,000,000 g/mol, preferably from about 50,000 g/mol to about 5,000,000 g/mol, and more preferably from about 100,000 g/mol to about 2,000,000 g/mol. The RPM macromolecules for use herein also have a viscosity from about 1 cP (0.001 Pa-s) to about 10 cP (0.010 Pa-s), and more preferably from about 1 cP (0.001 Pa-s) to about 5 cP (0.005 Pa-s), as measured by standard techniques.

The RPM macromolecule compositions of the present invention are copolymers, homopolymers, or terpolymers comprising a hydrophillic monomeric unit; at least one first anchoring monomeric unit; and may also include at least one optionally selected second anchoring monomeric unit. A filler monomeric unit may also be employed. These copolymer compositions may be advantageously used in aqueous-based water control treatment fluids to selectively control water production from hydrocarbon production wells. As used herein, the term “monomer” refers to molecules or compounds capable of conversion to polymers by combining with other like molecules or similar molecules or compounds. A “Monomeric unit” refers to a repeating molecular group or unit having a structure corresponding to a particular monomer. In this regard, the source of a given monomeric unit may or may not be the corresponding monomer itself.

As used herein, the term “monomeric anchoring unit” refers to components of a polymer that will preferentially bind, by either physical or chemical processes, to subterranean formation material and which therefore tend to retain the polymer to the formation material. Anchoring groups are typically selected to prevent a polymer from washing out of the formation due to fluid flow. Primary anchoring sites for the monomeric anchoring units are typically clay and feldspar surfaces existing in formation pores, channels and pore throats. With benefit of this disclosure, those of skill in the art will understand that particularly useful anchoring monomeric units are those having functional groups capable of hydrolyzing to form amine-based anchoring groups on the polymer. Examples include amide-containing monomeric units.

Advantageously, the disclosed co-polymers having the first anchoring monomeric units described herein may be utilized in well treatment methods to selectively reduce the permeability of a subterranean formation to water by a factor of about 10 or more, while at the same time leaving the permeability of the formation to oil virtually unchanged. Furthermore, the disclosed compositions, when introduced into a formation, tend to exhibit a high resistance to removal from water bearing areas of the formation over time.

Hydrophillic monomers may include both ionic and nonionic monomers. The term “nonionic monomer” refers to monomers that do not ionize in aqueous solution at neutral pH. Examples of suitable nonionic hydrophillic monomers include, but are not limited to, vinyl acylamide comonomers including, but not limited to, acrylamide, N-vinyl acetamide, N-vinyl-N-methyl acetamide, N,N-dimethyl acetamide, N-vinyl-2-pyrrolidone, N-vinyl formamide (VF), and N-ethenyl-N-alkyl acetamide, as well as mixtures of two or more of such comonomers. Ionic monomers may be either anionic or cationic. Examples of anionic monomers include, but are not limited to, alkaline salts of acrylic acid, ammonium or alkali salts of acrylamidomethylpropane sulfonic acid (“AMPS”), maleic acid, itaconic acid, styrene sulfonic acid, and vinyl sulfonic acid (or its ammonium or alkali metal salts). Examples of suitable cationic monomers include, but are not limited to, dimethyldiallyl ammonium chloride and quaternary ammonium salt derivatives from acrylamide or acrylic acid such as acrylamidoethyltrimethyl ammonium chloride.

In one embodiment, one or more hydrophillic monomeric units are typically employed and are based on AMPS (such as at least one of ammonium or alkali metal salt of AMPS, including sodium and/or potassium salts of AMPS), acrylic acid, an acrylic salt (such as sodium acrylate, N-vinyl pyrolidone, ammonium or alkali metal salts of styrene sulfonic acid, etc.), or a mixture thereof. It may be desirable to employ ammonium or alkali metal salts of AMPS for added stability, with or without one or more other hydrophilic monomers, in those cases where aqueous treatment and/or formation fluids contain high concentrations of divalent ions, such as Ca⁺², Mg⁺², and the like.

Optional second anchoring monomeric units may include any monomeric unit that will adsorb onto formation material. In one embodiment, examples of optional second anchoring monomeric units include at least one of dimethyldiallylammonium chloride, ammonium or alkali metal salts of acrylic acid, (such as sodium salts), or a mixture thereof.

Optional filler monomeric units may include any monomeric unit suitable for copolymerization with the other monomers in the composition. Desirable characteristics of filler monomer units are the ability to retain water solubility and/or relative low cost compared to other monomer units present in a copolymer. Filler monomer units may be based on, for example, monomers such as acrylamide, methylacrylamide, etc. In one embodiment, optional filler monomeric units include monomers such as acrylamide, methylacrylamide, and the like.

With benefit of the present disclosure, the disclosed compositions may be prepared using any method suitable for preparing co-polymers known to those of skill in the art. In one embodiment, monomers corresponding to the desired monomeric units in the copolymer are selected and polymerized in an aqueous monomer solution.

In one exemplary embodiment, a first N-vinylformamide monomer is combined with a hydrophillic monomer (such as ammonium or alkali metal salt/s of AMPS) and a filler monomer (such as acrylamides), in an aqueous base fluid, typically water. Other additives may include disodium ethylenediamine tetraacetate (Na₂EDTA), pH adjusting chemicals (such as potassium or sodium hydroxide), and a catalyst to initiate polymerization. Monomers with other anchoring groups may also be present.

Any relative proportion of the disclosed monomers that is suitable for polymerization and use in a water control treatment fluid may be combined in an aqueous solution for polymerization. However, in one embodiment, a first anchoring monomer is combined to be present in an amount of from about 2% to about 50% by weight of the total polymer composition, alternatively from about 5% to about 25% by weight of the total polymer composition. In another embodiment a first anchoring monomer is combined to be present in an amount from about 2% to about 50%, alternatively from about 5% to about 25%, by weight of the total polymer composition; ammonium or alkali metal salts of AMPS is combined so that AMPS-based monomer is present in an amount from about 0% to about 50%, alternatively from about 20% to about 30%, by weight of the total polymer composition; and acrylamide is combined to be present in an amount from about 20% to about 98%, alternatively from about 40% to about 65% by weight of the total polymer composition. In one embodiment, N-vinylformamide is utilized as the first anchoring monomer.

Where necessary or desirable, the pH of a monomer solution may be adjusted or neutralized prior to polymerization by, for example, addition of a base such as sodium hydroxide or potassium hydroxide. For example, the pH of an aqueous solution containing ammonium or alkali metal salts of AMPS may be adjusted to, for example, about 10 prior to the addition of N-vinylformamide and/or a second anchoring monomer or a filler monomer such as acrylamide. In one embodiment, a copolymer may be prepared by mixing the appropriate monomers into a tank of fresh water, followed by addition of a Na₂EDTA, pH adjuster and catalyst system to initiate polymerization. In one embodiment, ultimate pH range may be from about 6.5 to about 10.0 and alternatively from about 7.5 to about 9.5.

Additionally, the rate permeability modifier macromolecules of the present invention can optionally include organosilicon compounds, in order to afford modified viscosities and allow for further binding to substrate materials including quartz, clay, chert, shale, silt, zeolite, or combinations thereof.

Suitable organosilicon compounds suitable for use in the aqueous RPM macromolecule compositions described herein are those capable of forming water-soluble silanols by hydrolysis, include amino silanes, vinyl silanes, organosilane halides, and organosilane alkoxides, as well as combinations thereof. Suitable water-soluble amino silanes include, without limitation, 3-aminopropyltriethoxy silane and N-2-aminoethyl-3-aminopropyltrimethoxy silane. Vinyl silanes suitable for use in accordance with the present invention include but are not limited to vinyl tris-(2-methoxyethoxy) silane, aminopropyl triethoxy silane, aminoethyl triethoxy silane, aminopropyl trimethoxy silane, aminoethyl trimethoxy silane, ethylene trimethoxy silane, ethylene triethoxy silane, ethyne trimethoxy silane, ethyne triethoxy silane, 3,3,3-trifluoropropyl(2-trimethylsilylpiperidinyl)dimethoxysilane; 3,3,3-trifluoropropyl(2-trimethylsilyl-pyrrolidinyl)dimethoxysilane; 3,3,3-trifluoropropyl(2-(3-methylphenyl)piperidinyl)-dimethoxysilane; 3,3,3-trifluoropropyl(2-(3-methylphenyl)pyrrolidinyl)dimethoxysilane; 3,3,3-trifluoropropyl(1,2,3,4-tetrahydroquinolinyl)dimethoxysilane; 3,3,3-trifluoropropyl-(1,2,3,4-tetrahydroisoquinolinyl)dimethoxysilane; 3,3,3-trifluoropropyl-(decahydroquinolinyl)dimethoxysilane; 3,3,3-trifluoropropyl(bis(2-ethylhexyl)amino)-dimethoxysilane; and 3,3,3-trifluoropropyl(cis-2,6-dimethylpiperidinyl)dimethoxy-silane and combinations thereof.

Organosilane halides suitable for use in accordance with the present invention include those silanes of formula (I):

wherein X is halogen, R₁ is an organic radical, and R₂ and R₃ are independently hydrogen, or are the same or different halogens, or are the same or different organic radicals. Preferably, R₁ is a C₁-C₅₀ radical selected from the group of C₁-C₅₀ alkyl, C₁-C₅₀ alkoxy, C₁-C₅₀ alkoxyalkyl, C₂-C₅₀ alkenyl, C₂-C₅₀ alkynyl, an aralkyl group, or an aryl group having from 1 to 18 carbon atoms. Similarly, in accordance with the present invention, it is preferred that X in Formula (I) is a halogen selected from the group consisting of bromine, chlorine, fluorine, and iodine, with chlorine and bromine being preferred. R₂ and R₃, as indicated previously, can be hydrogen, the same or different halogens, or a C₁-C₅₀ radical selected from the group of C₁-C₅₀ alkyl, C₁-C₅₀ alkoxy, C₁-C₅₀ alkoxyalkyl, C₂-C₅₀ alkenyl, C₂-C₅₀ alkynyl, an aralkyl group, or an aryl group having from 1 to 18 carbon atoms.

Suitable organosilane halides of formula (I) suitable for use with the present invention include but are not limited to methyldiethylchlorosilane, dimethyldichlorosilane, methyltrichlorosilane, dimethyldibromosilane, diethyldiiodosilane, dipropyldichlorosilane, dipropyldibromosilane, butyltrichlorosilane, phenyltribromosilane, diphenyldichlorosilane, tolyltribromosilane, methylphenyldichlorosilane, propyldimethoxychlorosilane and the like.

Organosilane alkoxides suitable for use in accordance with the present invention include those silanes of formula (II):

wherein R₄, R₅, and R₆ are independently selected from hydrogen and organic radicals having from 1 to 50 carbon atoms, with the proviso that not all of R₄, R₅ and R₆ are hydrogen, and R₇ is an organic radical having from 1 to 50 carbon atoms and is not hydrogen. Preferably, R₄, R₅, R₆ and R₇ are independently hydrogen, C₁-C₅₀ radicals selected from the group of C₁-C₅₀ alkyl, C₁-C₅₀ alkoxy, C₁-C₅₀ alkoxyalkyl, C₂-C₅₀ alkenyl, C₂-C₅₀ alkynyl, an aralkyl group, or an aryl group having from 1 to 18 carbon atoms.

Suitable organosilane alkoxides of Formula (II) suitable for use within the present invention include but are not limited to methyltriethoxysilane, dimethyldiethoxysilane, methyltrimethoxysilane, divinyldimethoxysilane, divinyldi-2-methoxyethoxy silane, di(3-glycidoxypropyl) dimethoxysilane, vinyltriethoxysilane, vinyltris-2-methoxyethoxysilane, 3-glycidoxypropyltrimethoxysilane, 3-methacryloxypropyltrimethoxysilane, 2-(3,4-epoxycyclohexyl) ethyltrimethoxysilane, N-2-aminoethyl-3-propylmethyldimethoxysilane, N-2-aminoethyl-3-propyltrimethoxysilane, N-2-aminoethyl-3-aminopropyltrimethoxysilane, 3-aminopropyltriethoxysilane, tetraethoxysilane and the like.

The weight ratio of RPM macromolecule to organosilicon compound in the aqueous composition is generally from about 3:200 to about 20:4. The weight percentage of the RPM and organosilicon compound composite in the aqueous composition is generally from about 0.01 to about 25 weight percent. For instance, where the RPM macromolecule is PVA, the concentration ratio in parts per million of PVA RPM macromolecule to silicon in the organosilicon compound in the aqueous composition is generally from about 20,000:80 to about 200,000:40,000, preferably from about 50,000:800 to about 100,000:4,000. The weight percentage of the PVA RPM and silicon in the organosilicon compound composite in the aqueous composition is generally from about 2.0% to 24.00%, preferably from 5.0% to 10.5%, weight percentage. The concentration ratio in parts per million of polyacrylamide RPM macromolecule to silicon in the organosilicon compound in the aqueous composition is generally from about 100:80 to about 6,000:40,000, preferably from about 900:800 to about 3,000:4,000. The weight percentage of the polyacrylamide RPM and silicon in the organosilicon compound composite in the aqueous composition is generally from about 0.02% to 4.60%, preferably from 0.17% to 0.70%, weight percent.

As used herein, the terms “alkyl”, “alkylene”, “alkynyl”, “alkoxy”, “alkoxyalkyl”, “aryl”, “halogen”/“halide”, “heterocyclic”, and “aralkyl”, alone or in combination, have their usual chemical meaning, as known to those of skill in the art. Preferably, the alkyl radicals contain from about 1 to about 50 carbon atoms, and more preferably from about 1 to about 25 carbon atoms. In a similar manner, the alkylene and/or alkynyl radicals contain from about 2 to about 50 carbon atoms, and more preferably from about 2 to about 18 carbon atoms.

The term “substituted”, as used herein, indicates that one or more hydrogen on the designated atom or substituent is replaced with a selection from the indicated group, provided that the designated atom's normal valency is not exceeded, and the that the substitution results in a stable compound.

In one embodiment, the disclosed co-polymers may be polymerized from monomers using gel polymerization methods. In any case, polymerization is typically carried out in oxygen free or in a reduced oxygen environment. In this regard, a closed reactor in which oxygen has been removed and the reactor has been sparged and pressured with nitrogen gas, a solution where nitrogen gas is bubbled throughout the reacting solution, or other suitable polymerization methods known in the art may be employed with benefit of this disclosure. If so desired, a water control treatment fluid may be prepared at a well site.

With benefit of this disclosure, an aqueous base fluid may be any aqueous-base fluid suitable for well treatments known in the art including, but not limited to, fresh water, acidified water having pH range from 1.0 to 3.0, brine, sea water, synthetic brine (such as 2% KCl), produced formation water, and the like.

If so desired, optional mutual solvents may also be used with the aqueous composition of the invention. Mutual solvents, among other things, may act to remove hydrocarbons adhering to formation material. In this regard, any mutual solvent suitable for solubilizing hydrocarbons may be employed including, but not limited to, terpenes (such as limonene), C₃ to C₉ alcohols (such as isopropanol), glycol-ether (such as ethylene glycol monobutyl ether, “EGMBE”), or mixtures thereof.

It will be understood with benefit of the present disclosure that other additives known in the art for use in stimulation and well treatments may be employed in the practice of the disclosed method if so desired. For example, wetting agents, surfactants, thickeners, diversion agents, pH buffers, and the like can be used. In one embodiment, internal diverting materials may be employed if desired. Examples of suitable diverting agents include, but are not limited to, viscous water external emulsions, and are known to those of skill in the art. In one embodiment, an aqueous composition may be added to a salt solution, such as a 2% salt solution, wherein the salt is preferably potassium chloride.

The disclosed aqueous compositions may be used as the only component in an aqueous water control treatment fluid or may be combined with other components of stimulation fluid or other well treatment fluid (such as hydraulic fracturing fluids, acid fluids, surfactant squeeze treatment fluids, etc.).

Whether utilized as part of a stand-alone water control treatment fluid, employed in conjunction with another type of well treatment such as a stimulation treatment, or otherwise introduced into a well, the disclosed aqueous composition may be present in any concentration suitable for controlling water production in a subterranean formation. However, in one embodiment, one or more of the disclosed RPMs and/or RPM microgel compositions are present in the treatment fluid at a total concentration of from about 1 ppm to about 10,000 ppm polymer, and more preferably from about 3 ppm to about 6,000 ppm polymer, based on the total weight of the water control treatment fluid.

To reduce injection pressures during injection of a well treatment fluid, the potassium chloride may be added to the aqueous solution and the pH reduced to a low value, for example to about 1, just prior to introduction of the treatment fluid into a wellbore. Using this optional procedure helps minimize injection pressure and ensure the extent of penetration of the aqueous composition into the formation. The pH of a well treatment fluid may be lowered by the addition of any acidic material suitable for decreasing pH of the fluid to less than about 3, and alternatively between about 1 and about 3. Suitable acidic materials for this purpose include, but are not limited to, hydrochloric acid, formic acid and acetic acid, etc. With benefit of this disclosure, those of skill in the art will understand that addition of acidic material and adjustment of pH may be varied as desired according to treatment fluid characteristics and formation temperature conditions in order to optimize polymer retention and water control.

The aqueous composition may be batch prepared or prepared by continuous mix processes. For example, the water control treatment fluid may be first prepared in total, and then injected or otherwise introduced into a subterranean formation. This is referred to as a “batch mixing” process. In another embodiment, a water control treatment fluid may be prepared by continuous mix processes, wherein the treatment fluid components are mixed together while the fluid is simultaneously introduced into the wellbore.

Once a treatment fluid is prepared (either by batch or continuous mixing), the water control treatment fluid is introduced into the subterranean formation in any amount suitable for contacting a portion of a reservoir matrix of flow pathways. By “introduced” it is meant that a fluid may be pumped, injected, poured, released, displaced, spotted, circulated or otherwise placed within a well, wellbore, and/or formation using any suitable manner known in the art. In one embodiment, an amount of treatment fluid sufficient to treat the entire height of the producing interval having a radius of from about 3 to about 10 foot from the wellbore may be employed, however greater or lesser amounts are also possible.

The aqueous treating compositions of the present invention have particular applicability in those instances where the formation permeability is between from about 0.1 mD to about 10,000 mD. In high permeability (>1 to 1.5 Darcy) formations, optimum treatment results have been obtained. Core flow test results show effectiveness at a permeability as high as 8.0 Darcy (8,000 mD) under high rate flow conditions. Such hydrocarbon-bearing formations suitable for treatment with the compositions described herein are permeable formations including those comprised of diatomaceous materials, quartz, shale, zeolite, chert, clay, silt, carbonate, or combinations thereof.

Crosslinkers

As indicated previously, and in accordance with the present invention, the relative permeability modifier macromolecules of the present invention used as water redirecting agents can be crosslinked either internally, externally, or both. Such crosslinking is preferably performed using one or more chemical cross-linking techniques (vs. UV irradiation, biological crosslinking, etc.), and can occur during the synthesis of the RPM macromolecules, at the wellsite just prior to injection into an injector well (in the case of external crosslinking), or both. Crosslinkers suitable for use with the RPM macromolecules/microgels of the present invention include aldehydes, amides, acrylamides, isocyanates, metal salts, di- or poly-allyl based monomers, carbodiimide cross-linkers, and polyepoxide compounds. Most preferably, the RPM macromolecules of the present invention are crosslinked using aldehyde-based crosslinking techniques, acrylamide-based crosslinking techniques, or using polyepoxide compounds.

Examples of useful multifunctional crosslinking monomers include multifunctional acrylamides, and (meth)acrylates containing unsaturation at preferably 2, and optionally 3 or more sites on each copolymerizable comonomer molecule. In one embodiment, the multifunctional crosslinking monomers are selected from the group consisting of monomeric polyesters of acrylic or methacrylic acids and polyhydric alcohols; and monomeric polyalkenyl polyethers of polyhydric alcohols containing from 2 to about 6 polymerizable alkenyl ether groups per polyether molecule. Another exemplary crosslinking monomer is a monomeric polyester of an acrylic or methacrylic acid and a polyhydric alcohol containing from 2 to about 6 polymerizable α,β-unsaturated acrylic groups per polyester molecule. Other copolymerizable crosslinking monomers include divinyl ether, ethylene glycol dimethacrylate, (m)ethylene-bisacrylamide, allylpentaerythritol, and the like. The preferred crosslinking comonomers are somewhat water soluble and monomer soluble. Preferably, the acrylamide crosslinking agent used with the RPM macromolecules suitable for use in the methods of the present disclosure is methylene bis-acrylamide, or combinations of crosslinkers including methylene bis-acrylamide.

Aldehyde-based cross-linking techniques includes those techniques using a reagent containing two reactive aldehyde groups to form covalent cross-links between neighboring amino groups of monomer residues in the relative permeability modifier macromolecules described herein [Khor, E., Biomaterials, Vol. 18: pp. 95-105 (1997)]. Aldehydes suitable for use with the present invention include but are not limited to glutaraldehyde, formaldehyde, propionaldehyde, and butyraldehyde. Preferably, the aldehydes are glutaraldehyde or formaldehyde.

Polyepoxy based cross-linking techniques and agents include the use of compounds, such as short, branched polymers, terminating in reactive epoxy functionalities. Polyepoxy compounds suitable for use as cross-linking agents in the present invention include but are not limited to glycerol ethers, glycol, and glycerol polyglycidyl ethers.

Isocyanates are also suitable for use as cross-linking agents in the present invention. Generally, the isocyanates (R-NCO) react with primary amines to form a urea bond (R—H—CO—NH—R); difunctional isocyanates therefore have the ability to cross-link RPMs via lysine-like side chains. Isocyanates suitable for use as cross-linking agents in the present invention are preferably diisocyanates, including biphenyl diisocyanate, dimethoxy-4,4′-biphenyl diisocyanante, dimethyl-4,4′-biphenyl diisocyanate, 1,3-bis(isocyanatomethyl)benzene, phenyl diisocyanate, toluene diisocyanate, tolylene diisocyanate, diisocyanato hexane, diisocyanato octane, diisocyanato butane, isophorone diisocyanante, xylene diisocyanate, hexamethylene diisocyanante, octamethylene diisocyanante, phenylene diisocyanate, and poly(hexamethylene diisocyanate). Preferably, the isocyanate used as a cross-linking agent of the RPM macromolecules of the present invention is hexamethylene diisocyanate.

Carbodiimide cross-linking agents and techniques can also be used within the scope of the present invention. These agents react with the carboxyl groups of monomers within the RPM macromolecules/microgels to form isoacylurea derivatives/iso-peptide bonds [Khor, E., ibid.]. Carbodiimides suitable for use as cross-linking agents with the relative permeability modifier macromolecules of the present invention include but are not limited to N,N′-dicyclohexylcarbodiimide (DCC); N,N′-diisopropylcarbodiimide (DIC); N,N′-di-tert-butylcarbodiimide; 1-ethyl-3-(3-dimethylaminopropyl)carbodiimide (EDC; EDAC); water-soluble EDC (WSC); 1-tert-butyl-3-ethylcarbodiimide; 1-(3-dimethylaminopropyl)-3-ethylcarbodiimide; bis(trimethylsilyl)carbodiimide; 1,3-bis(2,2-dimethyl-1,3-dioxolan-4-ylmethyl)carbodiimide (BDDC, as described in U.S. Pat. No. 5,602,264); N-cyclohexyl-N′-(2-morpholinoethyl) carbodiimide; N,N′-diethylcarbodiimide (DEC); 1-cyclohexyl-3-(2-morpholinoethyl)carbodiimide methyl-p-toluenesulfonate [e.g., Sheehan, J. C., et al., J. Org. Chem., Vol. 21: pp. 439-441 (1956)]; oligomeric alkyl cyclohexylcarbodiimides, such as those described by Zhang, et al. [J. Org. Chem., Vol. 69: pp. 8340-8344 (2004)]; polymer bound DCC; and polymer bound EDC, such as cross-linked N-ethyl-N′-(3-dimethylaminopropyl)carbodiimide on JANDAJEL™. Additionally, N-hydroxysuccinimide (NHS), 1-hydroxy-7-azabenzotriazole (HOAt), or similar reagents can be utilized in conjunction with the carbodiimide to minimize internal rearrangement of the activated isoacylurea derivative and provide more efficient cross-linking.

Other chemical cross-linking agents suitable for use in the present invention to provide cross-linked RPM macromolecules for use in redirecting formation water to improve hydrocarbon recovery from subterranean formations include but are not limited to homobifunctional cross-linkers such as BMME, BSOCOES, DSP (a thio-cleavable cross-linker), DSS, EGS, water-soluble EGS, and SATA, as well as heterobifunctional cross-linking agents including GMB, MBS, PMPI, SMCC, SPDP, and MPH (maleimidopropionic acid hydrazide), MCH, EMCH (maleimidocaprionic acid hydrazide), KMUH (N-(κ-Maleimidoundecanoic acid)hydrazide), and MPBH (4-(4-N-MaleimidoPhenyl)butyric acid hydrazide), all available from Interchim (Cedex, France).

Specific examples of other crosslinking monomers suitable for use herein include but are not limited to trimethylol propane triacrylate (TMPTA), trimethylol propane trimethacrylate (TMPTMA); diethylene glycol diacrylate (DEGDA), diethylene glycol dimethacrylate (DEGDMA), trimethylene glycol diacrylate, butylene glycol diacrylate, methylene-bis-acrylamide, pentamethylene glycol diacrylate, octylene glycol diacrylate, glyceryl diacrylate, glyceryl triacrylate, neopentyl glycol diacrylate, the tetraacrylate ester of pentaerythritol, as well as combinations thereof.

It is understood that certain monounsaturated monomers may act in varying degrees to crosslink or branch the water soluble copolymer of the invention. For example, acrylate monomers with abstractable hydrogens, which can function as radical reactive sites, can in some embodiments of this invention, form a more branched or crosslinked polymer, thus affecting the preferred levels of the polyethylenic unsaturated crosslinking comonomers. An example of a monounsaturated monomer with an abstractable hydrogen is 2-ethylhexyl acrylate.

Optional heat-reactive, latent carboxy- or hydroxy-reactive internal crosslinking systems can be provided by the incorporation of carboxylic-group containing comonomers, and N-alkylol amides, for example, N-methylol acrylamide, N-propylol acrylamide, N-methylol methacrylamide, N-methylol maleimide, N-methylol maleamic acid esters, N-methylol-p-vinyl benzamide, and the like.

Known methods for optional post-polymerization crosslinking of carboxylic acid containing copolymers include, for example, U.S. Pat. No. 4,666,983 (crosslinking agent without any carrier solvent), using e.g. polyhydric alcohols, polyglycidyl ethers, polyfunctional amines and polyfunctional isocyanates. U.S. Pat. No. 4,507,438 and 4,541,871 utilize a difunctional compound in water with inert solvent or mixture of solvents. The difunctional compounds include glycidyl ethers, haloepoxies, aldehydes and isocyanates with ethylene glycol diglycidyl ether crosslinker. The solvents include polyhydric alcohols with ethylene glycol, propylene glycol and glycerine enumerated as preferred polyhydric alcohols. U.S. Pat. No. 5,140,076 teaches a water-solvent-crosslinker mixture. Crosslinkers such as polyhydric alcohol, diglycidyl ether, polyaziridene, urea, amine and ionic crosslinkers are suggested.

The crosslinked copolymers used herein form a stable, microgel solution as a result of obtaining a molecular size or weight, as characterized by the K-value test, of from about 220 to about 1000 (i.e., a K-value of from about 200 to about 1,000), and more typically have K-values of from about 220 to about 500. For example, in accordance with one aspect of the present invention, the relative permeability macromolecules of the present invention have a K value from about 220 to about 300.

The crosslinked copolymers of the present invention have no readily definable molecular weight due to the intermolecular crosslinking of the polymer chains. The Fikentscher value, or K-value measurement is a way to indirectly indicate molecular weight and/or size of the copolymers, accordingly. A higher K-value corresponds to a polymer of comparatively larger molecular weight and/or size or one that exhibits greater chain entanglement behavior.

To determine the K-value, the copolymer is typically dissolved to a 0.5% concentration in deionized water and the flow-out time is determined at about 25° C. by means of a capillary viscometer. This value gives the absolute viscosity (eta-c) of the solution. The absolute viscosity of the solvent is eta-0. The ratio of the two absolute viscosities gives the relative viscosity, z, $z = \frac{{eta} - c}{{eta} - 0}$ from the relative viscosities of the function of the concentration. The K-value can then be determined by means of the following equation: ${{Log}\quad z} = {{{\frac{75*k^{2}}{1 + {1.5{kc}}} + k}}*c}$ Any suitable capillary viscomter instrument known in the art (e.g., a Ubbelohde viscometer) can be used for the K-value measurements, in accordance with the present invention. Methods of Use

The RPM macromolecules and/or soft RPM microgel compositions of the present invention can be used to improve hydrocarbon recovery in subterranean operations by water flood intervention. More particularly, and as shown in FIG. 1, a series of drilled and completed producing wells (12) has a series of injection wells (10) loosely spaced apart from each other and perforated so as to be able to direct fluid (14) in the direction of the producer wells (12). According to one aspect of the present invention, injection fluid (14), which is an aqueous treating fluid comprising at least one RPM macromolecule as described herein, is directed into injector well or wells (10) by a pressure sufficient to move the fluid containing the RPM macromolecules into the hydrocarbon-bearing formation. The mixture that is ultimately used can optionally contain, in addition to the RPM macromolecules, one or more of a combination of chemical additives including wetting agents, surfactants, and caustic or alkaline materials, in order to enhance the redirection of water flow within the subterranean matrix within the formation. As fluid (14) is pumped into the formation, the RPMs in the treating fluid cause the water to be redirected through the formation, and in doing so displace the hydrocarbons (e.g., oil) toward the producing well or wells (12). Thereafter, the oil will be produced from the producer well (12) to the surface, preferably with very little water contamination which would necessitate separation of the oil from the water at the surface level.

Use of the relative permeability modifier macromolecules and/or RPM microgels in combination with the formations as described herein will allow substantially more hydorcarbonaceous fluids or oil to be produced from the formation than before the treatment methods described herein. This occurs because the flow of the RPM macromolecules in the aqueous treating fluid down and through the injector wells allow for substantially more formation contact by the RPM treating fluid mixture, which then redirects water from the formation toward the producer wells, and in doing so removes oil from the formation and alters the injection profile of the well.

The following examples are included to demonstrate preferred embodiments of the invention. It should be appreciated by those of skill in the art that the techniques disclosed in the examples which follow represent techniques discovered by the inventors to function well in the practice of the invention, and thus can be considered to constitute preferred modes for its practice. However, those of skill in the art should, in light of the present disclosure, appreciate that many changes can be made in the specific embodiments which are disclosed and still obtain a like or similar result without departing from the scope of the invention.

EXAMPLES Example 1 General Procedure for Parallel Core Flow Testing

The first step is to determine the test core dimensions and baseline properties. The test cores were placed into a suitable core-holder of a parallel flow test apparatus. The dry cores were then saturated with brine. Following saturation, the cores were heated to the test temperature(s) with the required confining and back pressures. The initial permeability to brine through both cores was then determined independently by establishing flow in an arbitrary injection direction (to simulate injection into the reservoir) at constant rate until steady state. AquaCon™ (available from BJ Services Company, Houston, Tex.) treatment fluid was then injected through the parallel flow apparatus, at a constant rate of approx. 0.3 ml/min, in the injection (treatment) direction. AquaCon™ treatment flow and pressure drops through both the high permeability and low permeability cores were measured simultaneously. The duration of this AquaCon™ treatment stage depended upon three things: i.) achievement of an 80-90% permeability reduction (for high permeability cores only); ii.) little or no noticeable permeability reduction at any given treatment concentration; and/or iii.) pore volume throughput based on previous tests.

Following the initial injection and measurements of the treatment fluid through the parallel-flow apparatus, brine was re-injected in the same direction at a constant rate of 0.3 ml/min in order to determine post-treatment steady state permeability to brine. These last two steps, treatment fluid injection and brine re-injection, were then repeated as necessary in order to further reduce the permeability to brine.

Example 2 Parallel Core Flow Test

The purpose of this test was to determine AquaCon™ (BJ Services Co., Houston, Tex.) effectiveness in reducing water flow through high permeability thief zones without significantly affecting the permeability in lower permeability zones. For this test, a high permeability sandstone core that was 10 times more permeable than the low permeability core (air permeability contrast of 10:1) was used. The result of the linear parallel core flood testing with 0.05% AquaCon™ is shown in Table 1 below. TABLE 1 Before Treatment After Treatment Ratio of AquaCon Ratio of High Treatment Permeability High Core K_(brine):Low % Pore Reduction K_(brine):Low Test Type K_(air) K_(brine) K_(brine) Conc. Volumes K_(brine) from Initial % K_(brine) 1 Sandstone 601 134 9.6 0.05 23 19 86% 1.9 59.4 14 0.05 10 29%

A total of 23 pore volumes of AquaCon™ treatment were injected through the parallel core flow apparatus. As expected, the majority of the AquaCon™ treatment flowed preferentially through the high permeability core that resulted in a significant brine permeability reduction (86%). In the low permeability core, there was less treatment invasion and hence a smaller brine permeability reduction (29%). Since a much larger injectivity loss occurs in the high permeability core, the AquaCon™ treatment significantly improved the injection profile, or distribution through the cores of contrasting permeabilities. Initially, the brine permeability contrast between the two cores was 9.6, compared to 1.9 after treatment. FIG. 2 illustrates the graphical representation of these test results. The results of this core-flow testing showed that AquaCon™ at very low concentrations could be applied to effectively treat injection wells.

All of the apparatus, methods and other particular embodiments disclosed and claimed herein can be made and executed without undue experimentation in light of the present disclosure. While the compositions and methods of this invention have been described illustratively in terms of preferred embodiments, it will be apparent to those of skill in the art that variations may be applied to the methods and/or apparatus and in the steps or in the sequence of steps of the methods described herein without departing from the concept and scope of the invention. Furthermore, no limitations are intended as relates to the details of construction or design as described herein. For example, the dimensioning illustrated in some of the drawing figures is exemplary in nature only, and it is to be understood that the particular embodiments described herein may be altered or modified by one of skill in the art, and that all such variations are considered within the scope and spirit of the present invention. 

1. A method for increasing hydrocarbon production from a production well in a hydrocarbon-bearing formation, wherein there is at least one injector well associated with the production well, the method comprising: introducing an aqueous treating composition comprising a relative permeability modifier (RPM) macromolecule into one or more injector wells.
 2. The method of claim 1, wherein the relative permeability modifier macromolecule is a microgel.
 3. The method of claim 2, wherein the microgel has a weight average molecular weight from about 10⁴ to about 10⁸ g/mol.
 4. The method of claim 2, wherein the microgel is present in the aqueous concentrate composition in a concentration of about 15,000 parts per million (ppm) to about 50,000 ppm.
 5. The method of claim 2, wherein the microgel has a K value from about 200 to about 1,000.
 6. The method of claim 5, wherein the microgel has a K value from about 250 to about
 300. 7. The method of claim 1, wherein the relative permeability modifier macromolecule has a viscosity from about 1 cP to about 5 cP.
 8. The method of claim 1, wherein the relative permeability modifier macromolecule is deformable.
 9. The method of claim 1, wherein the concentration of the relative permeability modifier in the aqueous treating composition introduced into the one or more injector wells is from about 3 ppm to about 6000 ppm.
 10. The method of claim 1, wherein the aqueous treating composition further comprises water, brine, or seawater.
 11. The method of claim 1, wherein the relative permeability modifier macromolecule is capable of redirecting a portion of the water flow through the hydrocarbon-bearing formation from the injector well(s) to the producer well.
 12. The method of claim 1, further comprising the step of providing an improved injection profile after the introducing step.
 13. A method for increasing hydrocarbon production from a production well in a hydrocarbon-bearing formation, wherein there is at least one injector well associated with the production well, the method comprising: introducing an aqueous treating composition comprising a relative permeability modifier (RPM) macromolecule into an injector well in a permeable formation, in an amount effective to enhance oil production from the production well; and continuing the injection of the RPM macromolecule into the injector well for a time sufficient to increase oil flow from the formation to the production well where it is subsequently produced to the surface via the producer well.
 14. The method of claim 13, wherein the RPM macromolecule is capable of redirecting water flow through the hydrocarbon-bearing formation to provide an improved injection profile.
 15. The method of claim 13, further comprising the step of forming a treating solution comprising at least one relative permeability modifier (RPM) macromolecule in an aqueous solution prior to, or during the introducing step.
 16. The method of claim 15, wherein the solution has a RPM macromolecule concentration from about 3 ppm to about 6000 ppm.
 17. The method of claim 15, wherein the forming of a treating solution step is carried out at the wellsite, immediately prior to, or during, the introducing step.
 18. The method of claim 13, wherein the relative permeability modifier has a weight average molecular weight from about 10,000 to about 50,000,000 g/mol.
 19. The method of claim 18, wherein the relative permeability modifier has a weight average molecular weight from about 50,000 to about 5,000,000 g/mol.
 20. The method of claim 19, wherein the relative permeability modifier macromolecule has a weight average molecular weight from about 100,000 to about 2,000,000 g/mol.
 21. The method of claim 13, wherein the relative permeability modifier macromolecule has a K value from about 200 to about
 1000. 22. The method of claim 21, wherein the relative permeability modifier macromolecule has a K value from about 200 to about
 600. 23. The method of claim 1, wherein the relative permeability modifier macromolecule comprises a homopolymer, a terpolymer, or copolymer of acrylamide.
 24. The method of claim 1, wherein the relative permeability modifier macromolecule comprises a quaternary ammonium salt, sulfonic acid salt, or mixture thereof.
 25. The method of claim 1, wherein the aqueous treating composition comprises a relative permeability modifier macromolecule and an organosilicon compound capable of forming a reactive silanol.
 26. The method of claim 1, wherein the relative permeability modifier macromolecule is crosslinked.
 27. The method of claim 1, wherein the hydrocarbon-bearing formation is a permeable formation comprised of diatomaceous materials, quartz, shale, zeolite, chert, clay, silt, carbonate, or combinations thereof.
 28. The method of claim 23, wherein the RPM is crosslinked.
 29. The method of claim 13, further comprising the step of injecting an external crosslinker into the hydrocarbon-bearing formation.
 30. The method of claim 9, wherein the relative permeability modifier macromolecule is present in the aqueous treating composition in an amount from about 10 ppm to about 3,000 ppm.
 31. The method of claim 26, wherein the crosslinked RPM macromolecule comprises: a terpolymer, copolymer or homopolymer comprising an anchoring monomer and a hydrophilic monomer; wherein the anchoring monomer is a vinyl formamide or a mixture thereof, and the hydrophilic monomer is an acrylamido sulfonic acid or a mixture thereof; and wherein the RPM macromolecule is capable of redirecting water flow through the hydrocarbon-bearing formation to provide an improved injection profile.
 32. The method of claim 26, wherein the crosslinked RPM macromolecule is deformable.
 33. The method of claim 1, wherein the aqueous treating solution is introduced at flow rates below flow rates necessary to cause fractures in the subterranean formation.
 34. The method of claim 26, wherein the RPM macromolecule is crosslinked either during polymerization or by an external crosslinker during the introduction step.
 35. The method of claim 26, wherein the crosslinked RPM macromolecule further comprises an acrylamide spacer monomer.
 36. The method of claim 26, further comprising: preparing an aqueous solution of an anchoring monomer, a hydrophilic monomer, and a spacer monomer; and polymerizing the monomers in the aqueous solution to form a RPM macromolecule; wherein the preparing and polymerizing take place prior to the injection step; wherein the anchoring monomer is a vinylformamide; wherein the hydrophilic monomer is an alkali metal, alkali earth metal, or quaternary ammonium salt of an acrylamido sulfonic acid; and wherein the spacer monomer is an acrylamide or mixture of acrylamides.
 37. The method of claim 36, wherein the preparing and polymerizing steps are carried out at or near the wellbore.
 38. The method of claim 36, wherein the polymerization step further comprises a crosslinking step to form a crosslinked RPM macromolecule, the crosslinking step comprising: contacting the RPM macromolecule with a crosslinking agent selected from the group consisting of aldehydes, amides, metal salts, epoxides, carbodiimides, di- or poly-allyl based monomers, or mixtures thereof.
 39. A method for increasing hydrocarbon production from a production well in a hydrocarbon-bearing formation, wherein there is at least one injector well associated with the production well, the method comprising: introducing an aqueous water-control fluid composition comprising a relative permeability modifier (RPM) macromolecule and an aqueous base fluid into an injector well in a permeable formation; and continuing the injection of the RPM macromolecule into the injector well for a time sufficient to increase oil flow from the formation to the production well where it is subsequently produced to the surface via the producer well; wherein the RPM macromolecule is capable of redirecting water flow through the hydrocarbon-bearing formation to provide an improved injection profile; and wherein the water control fluid composition is introduced into the hydrocarbon-bearing formation prior to, in conjunction with, or after a stimulation operation into the formation.
 40. The method of claim 39, wherein the RPM macromolecule is crosslinked.
 41. A method for enhancing hydrocarbon recovery from a reservoir or formation containing substantially immobile hydrocarbons, the method comprising: a) drilling and completing at least one injector well in a subterranean formation in proximity to a producer well, or converting a producer well into an injector well in proximity to other producer wells; b) directing an aqueous mixture comprising a relative permeability modifier (RPM) macromolecule into the injector well, wherein the RPM macromolecule is present in an amount effective to redirect water flow in the subterranean formation and thereby increase hydrocarbon flow therefrom; and c) continuing the injection of the aqueous mixture comprising a RPM macromolecule into the injector well for a time sufficient to increase flow of hydrocarbons from the formation towards the producer well, where it is subsequently produced to the surface via the producer well.
 42. The method of claim 41, further comprising, after step (c): injecting the aqueous mixture into the at least one injector well, aqueous mixture injection is ceased, and hydrocarbons are produced from the producer well.
 43. The method of claim 41, wherein the RPM macromolecule is crosslinked. 